Hydrocarbon oils derived from petroleum and similar sources contain varying amounts of nitrogen compounds and sulfur compounds. In the course of refining the oils it is often desirable to remove such compounds because they impart undesired properties such as disagreeable odor, corrosivity, poor color, and the like to saleable products. In addition, the compounds may have deleterious effects in various catalytic refining processes applied to oils, the nitrogen compounds in particular deactivating certain hydrocracking catalysts and tending to cause excessive gas and coke production in cracking processes. Various schemes have been devised for removing the nitrogen and sulfur compounds from oils, probably the most common and best suited process being catalytic hydrofining wherein the nitrogen and sulfur compounds are converted to NH.sub.3 and H.sub.2 S by reaction with hydrogen, usually promoted by the use of elevated temperatures and pressures and hydrogenation catalysts. Similar reactions of the nitrogen and sulfur compounds with hydrogen to form NH.sub.3 and H.sub.2 S also occur in other processes such as thermal and catalytic cracking, reforming, and hydrocracking, which are not specifically designed for this purpose. There are thus produced various reaction effluents containing NH.sub.3 and H.sub. 2 S.
The removal of HN.sub.3 and H.sub.2 S from such hydrocarbon reaction effluent streams may be accomplished by scrubbing with water, preferably at elevated pressure and low temperature. To obtain the desired extent of removal, however, it is often necessary to use a large amount of water so that a dilute aqueous solution of NH.sub.3 and H.sub.2 S is formed. This sour water generally has to be treated to remove the NH.sub.3 and H.sub.2 S before the water can be discharged under an NPDES permit.
In a typical prior art process for the upgrading of raw shale oil, the oil is subjected to mild hydrotreating conditions in order to remove the reactive metallic organic compounds commonly found in shale oil, for example: iron, arsenic, nickel, and vanadium. These compounds deposit on hydrotreating catalysts and eventually cause the catalyst to lose its hydrotreating activity. Moreover, the contaminated catalyst is not economically regenerable. As a result, the catalyst of choice is usually a low-cost, high-metal-capacity catalyst which is inherently unsuitable for the severe hydrotreating ultimately needed for complete upgrading of shale oil. Therefore, this mild hydrotreating is only the first step in the overall process. In the second step, a high activity catalyst is used at severe hydrotreating conditions to convert the shale oil nitrogen to NH.sub.3. This catalyst need not be able to withstand metallic compounds since they are essentially removed in the first step; the catalyst formulations can thus be optimized for nitrogen conversion. In one prior art process, the shale oil is subjected to a third step of upgrading in which waxy compounds are preferentially hydrocracked by means of a shape-selective catalyst in order to reduce the pour point of the shale oil.
Each of these prior art upgrading steps produces some NH.sub.3 and H.sub.2 S from the nitrogen and sulfur compounds contained in the shale oil. As described previously, the NH.sub.3 and H.sub.2 S are removed from the reaction effluent streams by scrubbing with water at elevated pressure and low temperature to form dilute aqueous solutions of NH.sub.3 and H.sub.2 S called sour water. In a typical prior art recovery process, these sour water streams are combined and fed to interconnected distillation columns operated at superatmospheric pressures wherein the NH.sub.3 and H.sub.2 S are recovered separately by stripping distillation.
H.sub.2 S vapors are withdrawn overhead from one column (H.sub.2 S stripper), and the bottoms from that column is passed to another column (NH.sub.3 stripper) where NH.sub.3 vapors are recovered by partially condensing the overhead vapors and recycling a portion of the condensate to the first column. Purified water is withdrawn as bottoms from the second column. This process works well for recovering NH.sub.3 and H.sub.2 S from petroleum-derived effluent streams where the NH.sub.3 to H.sub.2 S weight ratio is typically 0.5, but, when the effluent stream has a high NH.sub.3 to H.sub.2 S ratio (such as found in effluent streams from shale oil hydrotreating), ammonia levels further build up in the H.sub.2 S stripper column feed due to the ammonia in the recycle condensate stream. This further increase of the NH.sub.3 to H.sub.2 S ratio exacerbates an already difficult removal of H.sub.2 S in the H.sub.2 S stripper column and at a certain feed NH.sub.3 to H.sub.2 S ratio, the removal of H.sub.2 S becomes unfeasible.